In the conventional nitrogen oxide producing technology including gas turbines, engines and power generators, fossil fuels are burnt to produce heat energy. A byproduct of this combustion is flue gas. Flue gas contains various contaminants such as nitrogen oxide (NO.sub.x) and sulfur oxide (SO.sub.x). Pursuant to certain federal environmental regulations, NO.sub.x and SO.sub.x emissions must be minimized prior to flue gas entrance into the atmosphere. To rid flue gas of NO.sub.x and SO.sub.x, it has been the practice to utilize a catalytic reduction process and a desulfurization operation, respectively, as explained more fully below.
A catalytic reduction process employs a reducing agent and a catalyst surface. The reducing agent, ammonia (NH.sub.3) for example, is injected into the flue gas upstream of the catalyst surface. At the catalyst surface the reduction reaction occurs. The catalyst surface is generally a vanadium or tungsten oxide supported on alumina.
In the catalyst reduction reaction, NH.sub.3 reacts with NO.sub.x at the catalyst surface to yield nitrogen and water vapor as shown below: EQU 4NH3+4NO-4N2.fwdarw.4N2+6H20 EQU 4NH3+2NO2+O2.fwdarw.3N2+6H2O
A catalytic reduction reaction takes place at the catalyst surface at a speed controlled largely by the particular operating temperature. The catalytic reaction above requires an operating temperature in the range of 600.degree.-850.degree. F. to achieve a sufficient speed of reaction. That is, the reaction must take place within the limited period that the flue ga contacts and passes through the catalyst surface. Once the flue gas has traveled downstream of of the catalyst surface the reaction is essentially halted, rendering removal of additional NO.sub.x impossible. Failure to provide the proper operating temperature can slow down the speed of the catalytic reduction, rendering the reaction incomplete.
Conventionally, the necessary operating temperature for the particular catalytic reaction has been achieved by reliance on the high temperature of the flue gas as it departs the boiler. The temperature of the flue gas as it departs the boiler is approximately 600.degree.-800.degree. F. and absent a separate reheating operation the temperature declines as the flue gas travels through the heat extraction system reaching a low of approximately 175.degree. F. before entering the atmosphere. Thus, commonly the catalytic surface is placed near the boiler, the point in the heat extraction system where the flue gas can be expected to have attained a temperature in the operating range of approximately 600.degree.-850.degree. F.
As shown in FIG. 1, in conventional boiler applications to achieve the necessary operating temperature the catalyst surface 6' is placed after the boiler 2' and between the economizer 4' and the air heater 8'. In this arrangement the catalyst surface is upstream of the particulate control device 10' and the flue gas desulfurization unit 12'. With this conventional arrangement the catalytic reduction reaction occurs in advance of both the flue gas desulfurization and particulate control operations as explained fully below. This positioning sequence however, has proven unsatisfactory for at least the following reasons.
In the conventional operational sequence shown in FIG. 1, the catalytic process takes place in anticipation of the flue gas desulfurization operation, wherein sulfur oxides (SO.sub.x) contaminates are removed from the flue gas before exiting the plant. Consequently, SO.sub.x contaminates are present in the flue gas during the catalytic reduction process. This generates multiple problems.
For instance, NH.sub.3 can react with SO.sub.3 contaminants to form ammonium sulfate and bisulfate, a fine, sticky white particulate. The catalyst surface being of a porous honeycomb material provides pocket areas for receipt of ammonia sulfate and bisulfate. The catalyst surface can become clogged and rendered ineffective. Thereafter, it can be difficult, if not impossible, to remove the ammonia sulfate and bisulfate from the catalyst surface. Consequently, the catalyst surface must be replaced necessitating machine downtime an hindering operation efficiency.
Ammonium sulfate and bisulfate can also contaminate or clog the air heater surfaces. The air heater may then need to be shut down and manually cleaned with water jets and steam. A further loss in machine efficiency results. Additionally, ammonium sulfate and bisulfate may form a fine particulate which can act as a smoke cloud increasing stack plume opacity. Moreover, NH.sub.3, promotes the conversion of SO.sub.2 to SO.sub.3. Higher concentrations of SO.sub.3 increase the acid dew point of the flue gas, the temperature at which sulfuric acid droplets form by condensation. As a result, in order to avoid acid condensation in the air heater, exit temperature must be increased. An energy system loss results and overall boiler efficiency is compromised.
The positioning of the catalytic surface prior to the particulate control operation in the conventional arrangement produces still more problems. Coal, typically burnt to produce heat energy, leaves residual composites of the silica fly ash in the flue gas. The silica fly ash contains sulfur oxides (SO.sub.2) and alkaline metals. As shown in FIG. 1, normally this fly ash is removed by the particulate control equipment or an electrostatic precipitator located at a point in the system where the flue gas temperature has decreased to the rang of 300.degree. F. downstream of the catalytic reduction process.
The performance of the catalytic reaction prior to the particulate control operation in effect means that fly ash remains in the flue ga during the catalytic reduction reaction. The presence of fly ash during the catalytic reduction reaction causes several difficulties. The catalyst surface can become poisoned by the absorption of sulfur oxides or the condensation of alkaline metals contained in the fly ash. The catalytic surface can be essentially rendered inoperable. Also, the catalyst surface may be fouled and/or eroded by the fly ash.
Of further relevance to the present invention is the conventional desire to reheat particular types of flue gas which have become cooled prior to their entrance into the atmosphere. This process is necessary in conjunction with relatively cool flue gas, having a temperature of less than 175.degree. F. This is because where relatively cool flue gas exits the stack into the plant, water condensation immediately occurs causing unsightly white colored clouds of steam deposits. To avoid these white deposits, as illustrated in FIG. 1, flue gas is typically reheated just prior to its departure from the stack. The reheating procedure raises the flue gas temperature above 175.degree. F. facilitating an upward flue gas velocity or buoyancy. Consequently, better atmospheric dispersion of the flue gas can be accomplished. Nonetheless, a separate reheating operation demands excessive energy consumption and is a costly procedure.
The present invention solves the foregoing problems of the conventional catalytic reduction process and simultaneously provides an efficient means for the reheating of flue gas. The present invention eliminates the difficulties inherent in employing a catalytic reduction operation upstream of both the flue gas desulfurization and particulate control processes, as outlined above, by placing the catalytic reduction operation downstream thereof. In the present invention, the catalytic reduction process is positioned just before the flue gas exit from the stack. As a result, the flue gas temperature upon encountering the catalytic reduction operation is incidentally increased. A dual benefit results whereby the nitrogen oxide is removed and the flue gas is reheated. A separate reheating steps is avoided, energy is saved and an otherwise loss in system energy is made beneficial.